Measurement and Control of Liquid Level in Wells

ABSTRACT

Methods and apparatuses are disclosed for measuring and controlling liquid levels in a well. The apparatus may include a plurality of sensors, the plurality of sensors comprising: a first sensor coupled to the well, the first sensor configured to measure a casing pressure, a second sensor coupled to the well, the second sensor configured to measure a tubing pressure, and a third sensor coupled to a motor that is further coupled to the well, the third sensor configured to measure at least one characteristic of the motor, and a processor coupled to the plurality of sensors, wherein the processor calculates a level of liquid in the well based upon measurements of at least two of the plurality of sensors.

TECHNICAL FIELD

The present invention relates generally to controlling well parameters, and more particularly to actively controlling the liquid level in wells by using various surface measurements.

BACKGROUND

Oil and gas wells are ubiquitous in the petrochemical industry. During the production of oil and gas from a well, the downhole pressure of a well may drop below a level necessary to actively produce liquids from the well. A pump, sometimes termed a “beam pump” or a “sucker rod pump”, may be used to artificially lift the liquid in the well. In brief, these pumps often operate by moving a downhole pump barrel in and out of the liquid in the wellbore. One or more valves may be situated on the pump so that moving the pump in and out of the liquid in this fashion creates a sufficient amount of artificial lift to bring the liquid out of the well. If the liquid level in the wellbore declines to the point that the pump is no longer submerged, however, pump operation may suffer. For example, if the pump is no longer submerged, the pump may come in and out of contact with the liquid in the well as the pump is moved in and out of the wellbore. This may result in the pump pounding the surface of the liquid as it moves in and out of the liquid, a condition termed “fluid pounding”. Fluid pounding may undesirably cause pump failure by separating the pump from the sucker rod and/or by damaging the gear box or other surface components.

To minimize fluid pounding, conventional systems often monitor the mechanical load on the sucker rod and the position of the pump downhole by using a load cell and position switches mounted to the surface of the pump. Once the fluid pounding condition is noticed, conventional systems often deactivate the pump for a predetermined period of time. This approach has several drawbacks. First, the pump must actually be experiencing a fluid pounding condition before it will be shut off, which may be harmful to the pump components. Second, the pump is powered down for a predetermined period of time regardless of the actual liquid level in the wellbore. Thus, when the predetermined time expires and the pump is turned back on, the fluid pounding condition may still exist. Also, because conventional systems turn the pump back on after a predetermined period of time, the pump may be off even when the liquid level has risen to a point where the fluid pounding condition would no longer exist if the pump were running. Fourth, analyzing the load cell for load characteristics may be complex. Lastly, maintenance costs associated with the load cell and position switches may undesirably add to the overall costs of the operating the well thus reduce profitability. Accordingly, there is a need for a system and method for controlling downhole liquid levels that addresses one of more of these deficiencies.

SUMMARY

Methods and apparatuses are disclosed for measuring and controlling liquid levels in a well. Some embodiments may include apparatuses that further include a plurality of sensors, the plurality of sensors comprising: a first sensor coupled to the well, the first sensor configured to measure a casing pressure, a second sensor coupled to the well, the second sensor configured to measure a tubing pressure, and a third sensor coupled to a motor that is further coupled to the well, the third sensor configured to measure at least one characteristic of the motor, and a processor coupled to the plurality of sensors, wherein the processor calculates a level of liquid in the well based upon measurements of at least two of the plurality of sensors.

Some embodiments may include methods that further include calculating liquid levels in a well, the method may comprise: reading a plurality of data measurements, calculating an annulus liquid level based upon at least two of the plurality of data measurements, determining if the liquid level is decreasing, and in the event that the liquid level approaches a predetermined location within the well, shutting off a motor coupled to the well.

Some embodiments may include a system comprising: a processing unit and a plurality of sensors coupled to the processing unit and coupled to at least one well within the plurality of wells. The plurality of sensors may comprise: a first sensor coupled to the at least one well within the plurality of wells, the first sensor configured to measure a casing pressure, a second sensor coupled to the at least one well within the plurality of wells, the second sensor configured to measure a tubing pressure, and a third sensor coupled to a motor that is further coupled to the at least one well within the plurality of wells, the third sensor configured to measure at least one characteristic of the motor, wherein the processing unit calculates a level of liquid in the well based upon measurements of at least two of the plurality of sensors.

Some embodiments may include an apparatus for measuring data from a well, comprising means for receiving at least one signal pertaining to the well, means for calculating a liquid level based upon the at least one signal, means for determining if the liquid level is decreasing, and in the event that the liquid level approaches a predetermined location within the well, means for shutting off a motor coupled to the well.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 illustrates an exemplary well pumping system.

FIG. 2 illustrates an exploded view of a cross section of the well.

FIG. 3 illustrates exemplary operations to control pump activity.

FIG. 4 illustrates an exemplary embodiment for measuring the level of liquid in a well.

The use of the same reference numerals in different drawings indicates similar or identical items.

DETAILED DESCRIPTION OF THE INVENTION

The following discussion describes various embodiments that may determine the liquid level in a well. Although one or more of these embodiments may be described in detail, the embodiments disclosed should not be interpreted or otherwise used as limiting the scope of the disclosure, including the claims. In addition, one skilled in the art will understand that the following description has broad application. Accordingly, the discussion of any embodiment is meant only to be exemplary and is not intended to intimate that the scope of the disclosure, including the claims, is limited to these embodiments.

Embodiments are disclosed that may allow the liquid level in a well to be calculated based upon one or more surface side measurements. The measurements may be based upon surface side parameters. For example, in some embodiments the measurements may be associated with the power consumption of a surface side motor, the motor's revolutions per minute, pressure in the casing of the well, pressure in the tubing of the well, etc. These parameters may be measured using sensors conventionally used at the surface of a well, and therefore, specialized load cells and/or position sensors may be unnecessary in determining the liquid level and in determining whether a fluid pounding condition is present. By calculating the liquid level, the pump's operation may be controlled to turn off prior to fluid pounding occurring, and therefore, the pump's components may be less likely to be damaged. Furthermore, the pump's operation may be controlled to turn back on without waiting for a predetermined time to expire so that the amount of time that the pump is on may be maximized.

FIG. 1 illustrates a pump jack 100 capable of providing artificial lift to liquid produced from a well 105 drilled to a depth of a producing formation 103. As used herein, the term “producing formation” generally refers to a strata of earth that may include liquid and/or gas of interest. While the producing formation 103 may be shown as generally orthogonal to the tubing and casing (e.g., as shown in FIG. 2) this is for the sake of discussion. In fact it should be recognized that the producing formation 103 may be oriented in various ways.

The liquid produced from the well 105 may be any variety of liquids such as oil and/or condensate (both of which are herein referred to as “oil”), water, and/or combinations of oil and water, which are sometimes called “emulsion”. Depending upon the embodiment, the pump jack 100 may include a motor 110, a gear box 115 coupled to the motor, a beam 120 (sometimes referred to as a “walking beam”) coupled to the gearbox 115, and a rod 125 coupled to the walking beam 120 via a weighted head 130 (sometimes referred to as the “horse head” of the pump jack 100). During operation, the motor 110 may move a set of pulleys 132, which in turn may move a counter weight 135 to move the walking beam 120 and horse head 130 about a supporting structure 140. Moving the walking beam 120 in this manner may result in the rod 125 moving up and down, thereby causing a downhole pump 145 coupled to the rod 125 to move within the liquid introduced to the production casing 205 from the producing formation 103. As the downhole pump 145 moves within the liquid, the liquid may be pushed to the surface through the interior of the production tubing 220 (shown and discussed in greater detail with regard to FIG. 2).

As mentioned above, if the liquid level (designated as “LL” in FIG. 2) drops to a level where the pump 145 is not fully submerged, then the rod 125, the pump 145, and/or the pump jack 100 may be damaged. Some embodiments may prevent this damage by actively monitoring the liquid level within the annular space between the production casing 205 and the production tubing 220 and shutting the pump jack 100 off when the liquid level approaches a level where the pump 145 is no longer submerged. Furthermore, some embodiments may calculate this liquid level without implementing specialized load cells and/or position sensors. For example, the liquid level may be determined by monitoring the well production data, pump data, and/or motor data. In other embodiments, one or more downhole sensors may be employed to measure the liquid level.

FIG. 2 depicts an exploded view of a section 200 of the well 105. The section 200 illustrates a casing 205 oriented in the ground to at least a depth of the producing formation 103. The casing 205 may be made of a rigid material, such as metal piping, in order to prevent the walls of the well 105 from caving in and/or to prevent the well contents within the casing 205 (such as oil and gas), from entering another formation other than the producing formation 103. In some embodiments, the well 105 may be drilled in such a manner that the well 105 is larger than the outside diameter of the casing 205. In these embodiments, the annulus between the production casing 205 and the formation 103 and the bottom portion of the production casing 205 may be filled with a sealant 215, such as concrete or clay grout as shown.

The section 200 also illustrates a production tubing 220 oriented within the production casing 205 leaving an annulus 225 between the production tubing 220 and the production casing 205. The production casing 205 may extend from surface side to the bottom of the well 105. The production tubing 220 may extend from surface side to a point above the introduction of liquids and/or gas from the producing formation 103. The overall length of the tubing is designated in FIG. 1 as “TL”. During operation, liquid from the producing formation 103 may permeate one or more perforations 227 in the casing 205 and sealant 215 (shown in FIG. 2) such that when the rod 125 and the pump 145 move within the production tubing 220, liquid may be forced from the producing formation 103, through the perforations 227, and up through the production tubing 220. Because the producing formation 103 may include mixtures of oil, gas, and/or water, the emulsion may be collected and produced through the tubing 220 whereas the annulus 225 may be used to collect and produce the gas.

Referring still to FIG. 1, the liquid and gas collected downhole may be removed at the surface via a liquid pipe 150 and a gas pipe 155 respectively. The gas pipe may be coupled to a measurement device 156, which in some embodiments may include a plate with an orifice that is situated within the gas pipe. During operation, the measurement device 156 may measure temperature, pressure, and differential pressure for volume calculations.

In accordance with some embodiments, the liquid level LL may be calculated by measuring various parameters such as the casing pressure, tubing pressure, motor power consumption, motor speed, and/or physical parameters of the well 105, such as the tubing length TL. In some embodiments, the liquid flow in the pump 145 over a single lift cycle and the pressure at the inlet of the pump 145 may be calculated. An exemplary LL calculation will now be presented based upon one or more surface side parameters available without implementing specialized load cells and/or position sensors often used in conventional systems. Although exemplary LL calculations are presented herein, it should be appreciated that numerous methods of calculating LL based upon one or more surface side parameters may be implemented that fall within the spirit and scope of this disclosure.

Equation (1) represents an exemplary equation that may be used to calculate the flow rate Q in the pump 145 over a single lift cycle.

$\begin{matrix} {Q = \frac{\pi \cdot S \cdot R \cdot E_{v} \cdot A_{IT}}{r \cdot C_{v}}} & {{Eq}.\mspace{14mu} (1)} \end{matrix}$

Turning to Equation (1), the variable S is the distance traveled by the rod 125 with each cycle of the pump jack 100. Since the distance traveled by the rod 125 may be controlled by the up and down motion of the horse head 130, the value of S may be a known value. The variable R is the speed of the motor 110 and may be measured in revolutions per minute (RPMs). In some embodiments, the RPMs may be measured using a magnetic pickup sensor 157 positioned adjacent to the motor 110 and coupled to a processor 160. The processor may be preprogrammed to sample values from the sensor 157 and determine the RPMs based upon these measurements. Furthermore, the processor 160 also may be preprogrammed with the value of the distance the rod 125 travels with each cycle S, where the completion of a cycle may be related to a predetermined number of revolutions of the motor 110. In this manner, the processor 160 may take a variety of forms such as a programmable logic controller, a microcontroller, and/or a computer system to name but a few implementations.

The processor 160 may be coupled to a host computer 185, which may be located in a geographically different location than the processor 160 in some embodiments. That is, the host computer.185 may be located in a remote field office in a field of wells, or in some embodiments, the host computer 185 may be located in a vehicle that travels within the field of wells. Thus, the host computer 185 may be hardwired to the processor 160 and/or wirelessly coupled to the processor 160.

Referring back to Equation (1), the variable E_(v) in Equation (1) is the volumetric efficiency of the pump 145. Generally speaking, the volumetric efficiency E_(v) refers to the theoretical flow rate of the pump 145 compared to the actual liquid flow rate from the liquid pipe 150. The actual liquid flow rate from the liquid pipe 150 is often measured as part of the data associated with the production of the well 105. Thus, the volumetric efficiency E_(v) may characterize the amount of leakage, or losses in volume in the pump 145, per lift cycle. Exemplary values for the volumetric efficiency may range from 90-98%. The variable A_(IT) is the cross sectional area inside the tubing 220 as shown in Equation (2), where ID_(T) is the inside diameter of the tubing 220 as indicated in FIG. 2.

$\begin{matrix} {A_{IT} = {\pi \cdot \left( \frac{I\; D_{T}}{2} \right)^{2}}} & {{Eq}.\mspace{14mu} (2)} \end{matrix}$

The variable r in Equation (1) is the number of motor revolutions performed per lift cycle of the pump jack 100. The variable C_(v) is the volume conversion factor. In some embodiments, the stroke length S and the inside diameter ID_(T) are measured in inches and therefore the volume conversion factor variable C_(v) may be 231 inches³ per gallon. Thus, the dimensions for the flow rate of Equation (1) may be gallons per minute.

Equation (3) represents an exemplary equation that may be used to calculate the pressure P_(INLET) at an inlet to the pump 145 using the flow rate Q calculated in Equation (1).

$\begin{matrix} {P_{INLET} = {\left( {{T\; P} + \left( \frac{T\; {L \cdot G_{L}}}{A_{AT}} \right)} \right) - \left( \frac{W \cdot E_{M}}{Q \cdot C_{P}} \right)}} & {{Eq}.\mspace{14mu} (3)} \end{matrix}$

Turning to Equation (3), the variable TP is the tubing pressure as measured at the liquid pipe 150. In some embodiments, the tubing pressure TP may be measured using a pressure transducer 165 coupled to liquid pipe 150. In some embodiments, the units for the tubing pressure TP is pounds per inch² gauge (PSIG). Akin to the measurements described with regard to Equation (1), the processor 160 may make analog measurements from such a transducer and calculate digital versions of the same for use in further processing. The variable TL is the tubing length (in feet) and is known when the pump jack 100 is constructed. The variable G_(L) is the gradient of the liquid being removed from the well 105 in pounds per foot. The variable A_(AT), as shown in Equation (4), is the cross sectional area of an annulus 230 formed between the outside diameter of the rod 125 (labeled as R_(D) in FIG. 2), and the area inside the tubing A_(IT) (expressed in Equation (2)).

$\begin{matrix} {A_{AT} = {A_{IT} - {\pi \left( \frac{R_{D}}{2} \right)}^{2}}} & {{Eq}.\mspace{14mu} (4)} \end{matrix}$

The variable W in Equation (3) is power consumed by the motor 110 as it operates the pump jack 100. In some embodiments, the power consumed W may be measured by the processor 160 by monitoring an ammeter 170 and/or wattmeter 175 coupled to the motor 110. The variable Q in Equation (3) is the flow rate calculated in Equation (1) in gallons per minute. The variable C_(P) is the power conversion factor. In some embodiments, the variable C_(P) is equal to 0.435 Watts-Minutes-Inches² per Pound-Gallon. The variable E_(M) is the mechanical efficiency of the pumping system, which may include the pump 145 and/or the pump jack 100. In some embodiments, the value of the variable E_(M) may be measured directly in the field after one or more of the components shown in FIG. 1 have been deployed.

The liquid level LL in the well 105 may be calculated by equating the downhole pressure at the pump inlet (per Equation (3)) with the downhole pressure profile of the casing 205, also P_(INLET) as shown in Equation (5), and then solving for the liquid level LL.

P _(INLET) =CP+P _(GC) +P _(LC)   Eq. (5)

Referring to Equation (5), the variable CP is the casing pressure at the gas pipe 155. In some embodiments, the processor 160 may couple to a pressure transducer 180 that is coupled to the gas pipe 155, and therefore, the processor may make analog measurements and convert the same to digital form for further processing and/or transmission. The variable P_(GC) in Equation (5) is the pressure of the head of the gas in the casing and may be calculated as shown in Equation (6), where the units for Equation (6) may be Pounds per Foot in some embodiments.

$\begin{matrix} {P_{GC} = \frac{G_{G} \cdot \left( {{T\; L} - {C\; L} - {L\; L}} \right)}{A_{A\; C}}} & \left( {{Eq}.\mspace{14mu} (6)} \right. \end{matrix}$

The variable G_(G) is the gradient of the gas being removed from the annulus 225. As mentioned above, the variable TL is the tubing length (in feet) and is known when the tubing 220 is installed in the well 105. The variable A_(AC) is the cross sectional area of the annulus 225 as shown in Equation (7), where the variable ID_(C) is the inside diameter of the casing 205 in inches and the variable OD_(T) is the outside diameter of the tubing 230 in inches.

$\begin{matrix} {A_{A\; C} = {\pi\left( {\left( \frac{I\; D_{C}}{2} \right)^{2} - \left( \frac{O\; D_{T}}{2} \right)^{2}} \right)}} & {{Eq}.\mspace{14mu} (7)} \end{matrix}$

Referring to Equation (8), an equation for the calculating the head pressure of the liquid in the casing P_(LC) is shown. The variable G_(L) is the gradient of the liquid being removed from the annulus 225 and the other variables in Equation (8) have been described above.

$\begin{matrix} {P_{LC} = \frac{\left( {{G_{L} \cdot L}\; L} \right)}{A_{A\; C}}} & {{Eq}.\mspace{14mu} (8)} \end{matrix}$

Referring momentarily back to Equation (5), after Equations (6), (7), and (8) are substituted into Equation (5), an expression for P_(INLET) may be derived. This expression for P_(INLET) may be set equal to the expression for P_(INLET) of Equation (3) and the resulting expression may be solved for the liquid level LL. Making these substitutions and solving for the liquid level LL yields Equation (9).

$\begin{matrix} {{L\; L} = {A_{A\; C}\left\lbrack \frac{\begin{bmatrix} {{T\; P} - {C\; P} + \left( \frac{T\; {L \cdot G_{L}}}{A_{AT}} \right) -} \\ {\left( \frac{W \cdot E_{M}}{Q \cdot C_{P}} \right) - {G_{G}\left( {{T\; L} + {C\; C}} \right)}} \end{bmatrix}}{\left( {G_{L} - G_{G}} \right)} \right\rbrack}} & {{Eq}.\mspace{14mu} (9)} \end{matrix}$

As shown in FIG. 1, the variable CC in Equation (9) represents the distance from the center of the liquid pipe 150 to the center of the gas pipe 155. (The rest of the variables in Equation (9) were addressed above.) The liquid level LL in Equation (9) may be calculated by relying upon a combination of variables that are known when the tubing 220 is installed in the well 105 (e.g., diameter of tubing 220), variables that may be measured during operation of the pump jack 100 (e.g., motor RPMs), and variables that may be calculated based upon the measured variables (e.g., liquid flow rate). Notably, the variables for calculation of Equation (9) may be measured and the pump jack 100 may be prevented from entering a potentially damaging condition. Also, maintaining the sensors, such as the sensors 157, 170, and/or 175, may be more cost effective than maintaining the load cells and position sensors used in conventional systems to detect fluid pounding. Furthermore, operation of the pump jack 100 may be based upon the actual liquid level LL allowing the pump jack 100 to be shut down before the liquid level LL gets so low that fluid pounding occurs, which may result in prolonging the life of the pump jack 100.

FIG. 3 illustrates an exemplary operation 300 that may be implemented by the processor 160 in controlling operation of the pump jack 100. The operations shown in FIG. 3 may be used to calculate the liquid level LL in the well 105 and/or store well trending information in the processor 160. In block 305, various measurements may be made, such as power consumed by the motor 110, current consumed by the motor 110, RPMs of the motor 110, casing pressure CP, and tubing pressure TP to name but a few. As mentioned previously, this may include the processor 160 measuring analog measurements from one or more sensors 157, 165, 170, 175, and/or 180, and converting these analog signals to digital form. In block 310, the calculated variables may be calculated by the processor 160, for example, by executing operations that perform the calculations of Equations (1)-(9). If well production (for example as measured coming out of the liquid pipe 150) is not stable and/or the liquid level is not increasing, then the processor 160 may determine if the liquid level LL is approaching the pump 145 as shown in block 325. If the liquid level LL is approaching the pump 145, then the motor 110 and/or pump 145 may be shut off per block 320.

Depending upon the embodiment and/or the particular pump 145 implemented, the liquid level LL that triggers the condition of block 325 may vary. For example in some embodiments, the liquid level LL at which the pump jack 100 is shut off may be where the pump 145 is no longer submerged. In the event the liquid level LL does not trigger the condition of block 325, then the total on time of the pump 100 may be determined and compared with a predetermined maximum on-time for the pump 145. This is illustrated in block 330. In the event that the pump on-time exceeds a predetermined maximum value, then the motor 110 may be shut off per block 320. If, however, the pump on-time does not exceed this predetermined value, control may flow back to block 305 as shown.

While the motor 110 is shut off, the pump 145 also may be shut off. In this situation, the system no longer may be able to calculate the liquid level LL in the annulus using motor characteristics—i.e., the wattmeter 175 may read zero watts, the calculated horsepower may be zero HP, and/or the downhole pressure may not be calculable. Thus, in order to determine when the pump should be re-started with the motor off, it may be based on any number of non-liquid level LL parameters. The non-liquid level LL parameters may include a declining casing pressure CP, a increasing gas production flow rate, and/or a preset motor off time to name but a few. In this manner, the pump 145 and/or the motor 110 may be reactivated (as shown in block 335) if certain conditions occur. For example, as illustrated in block 340, if the casing pressure CP declines below a predetermined value then the motor 110 and/or pump 145 may be reactivated. In some embodiments, the measured casing pressure CP value may be approximately 100 psig. For example, a typical operating casing pressure CP in coal-bed-methane wells may vary between 0 psig to 150 psig.

As mentioned above, the measured CP along with gas production flow rate data may be useful to determine the re-start condition. Where there is decreasing CP and increasing gas flow rate, the liquid level LL will most likely be increasing therefore the condition may be good to start the pump to remove fluids. In some wells increasing CP and increasing gas flow rate may also indicate an increasing liquid level LL therefore the condition may be good to start the pump to remove fluids. If the casing pressure CP is above this predetermined value, then the well's gas production may be checked to see if it is within a predetermined value as shown in block 345. The well's liquid and gas production may be determined by examining flow meters (not necessarily shown in FIG. 1) coupled to the liquid pipe 150 and the gas pipe 155. In some embodiments, the gas production may be calculated according to standards set forth by the American Gas Association (AGA), such as AGA-3 and AGA-8. If the well production is above this predetermined level, then the motor 110 and/or pump 145 may be reactivated. In the event that the well production is not above this predetermined value, then the motor 110 and/or pump 145 may remain off until the processor 160 has determined that a predetermined elapsed time has transpired per block 350. Once the processor 160 determines that the predetermined time has elapsed, then the motor 110 and/or pump 145 may be reactivated per block 335. In the event that the predetermined time has not elapsed, or if the motor 110 and/or pump 145 has been reactivated per block 335, then control flows back to block 305, where the processor 160 may again read and store various measured variables, for example, as part of determining the trends associated with well 105.

As described above, the liquid level LL in block 325 may be based upon calculations, such as those presented in Equation (9). In some embodiments, the liquid level LL may be determined by one or more sensors located in the well 105. As shown in FIG. 4 the well 105 may include one or more floating objects 405A-B. In some embodiments, the floating objects 405A-B may include lightweight spherical structures, such as hollow plastic spheres, each having a radio-frequency-identification (RFID) transmitters. The RFID transmitters may be any variety, such as passive, active, and/or semi-passive.

During operation, the RFID transmitters may transmit one or more signals to one or more receiving antennas 410A-B positioned in the well 105. In some embodiments, the one or more receiving antennas 410A-B may be integrated within the casing 205. In other embodiments, the antennas 410A-B may be suspended from a cable 415 in the annulus 225. Further, the one or more antennas 410A-B may be positioned in predetermined locations within the well 105 such that the desired liquid level LL is located halfway between the antenna 410A and 410B. The floating objects 405A-B may change position with the change in liquid level LL of the well 105, and therefore, the antennas 410A and/or 410B may receive signals from the floating objects 405A-B as they approach the antennas 410A-B. In some embodiments, the antennas 410A-B may be coupled to the processor 160 and the processor 160 may be used to determine the overall liquid level LL in the well 105.

Although two objects 405A-B are shown in FIG. 4, it should be appreciated that any number of floating objects are possible. Also, in some embodiments, each of the objects 405A-B may have different densities such that they may float at different levels within the well 105. Further, some embodiments may include multiple receivers 410A-B such that the position of the floating objects 405A-B, and therefore the liquid level LL—may be triangulated, for example by the processor 160. In addition, although FIG. 4 illustrates wirelessly coupling the floating objects 405A-B to the antennas 410A-B, it should be appreciated that the floating objects 405A-B may be physically coupled to the antennas or other such pickup device. For example, the floating objects 405A-B may be hardwired to a pickup sensor to indicate liquid level instead of using RFID tags.

Although the present invention has been described with reference to preferred embodiments, persons skilled in the art will recognize that changes may be made in form and detail without departing from the spirit and scope of the invention. For example, the disclosed methods of determining a well's liquid levels and trending data may be applied to naturally producing wells (i.e., wells that do not use the pump jack 100) by modifying the calculations described above accordingly. 

1. An apparatus for measuring data from a well, the apparatus comprises: a plurality of sensors, the plurality of sensors comprising: a first sensor coupled to the well, the first sensor configured to measure a casing pressure; a second sensor coupled to the well, the second sensor configured to measure a tubing pressure; and a third sensor coupled to a motor that is further coupled to the well, the third sensor configured to measure at least one characteristic of the motor; a processor coupled to the plurality of sensors, wherein the processor calculates a level of liquid in the well based upon measurements of at least two of the plurality of sensors.
 2. The apparatus of claim 1, wherein the at least one characteristic of the motor is selected from the group consisting of the motor's revolutions per minute, the motor's current consumption, or the motor's power consumption.
 3. The apparatus of claim 1, wherein a first pressure at the bottom of the well is calculated based upon one or more of the following: the tubing pressure, the at least one motor characteristic, and/or a weight associated with liquid in a tubing.
 4. The apparatus of claim 3, wherein the weight associated with liquid in the tubing is expressed as a pressure measurement.
 5. The apparatus of claim 3, wherein a second pressure at the bottom of the well is calculated based upon one or more of the following: the casing pressure, a weight associated with liquid in a casing, and/or a weight associated with gas in the casing.
 6. The apparatus of claim 5, wherein the first and second pressures at the bottom of the well are equated to determine the level of liquid in the well.
 7. The apparatus of claim 1, further comprising a fourth sensor coupled to a liquid pumped to the surface by the pumping unit, wherein the processor is configured to calculate liquid flow rate using a measurement from the fourth sensor.
 8. The apparatus of claim 7, further comprising a fifth sensor coupled to a gas flowing in an annulus, the processor configured to calculate gas flow rate using a measurement from the fifth sensor.
 9. The apparatus of claim 8, wherein the gas flow calculation is based upon one or more standards set forth by the American Gas Association.
 10. A method of calculating liquid levels in a well, the method comprising the acts of: reading a plurality of data measurements; calculating an annulus liquid level based upon at least two of the plurality of data measurements; determining if the liquid level is decreasing; and in the event that the liquid level approaches a predetermined location within the well, shutting off a motor coupled to the well.
 11. The method of claim 10, wherein the predetermined location within the well includes a location above a pump situated in the well, and in the event that the liquid level is approaching the pump's location in the well, the method further comprises the act of shutting off the motor.
 12. The method of claim 10, further comprising the act of shutting off the motor in the event that a predetermined period of time elapses.
 13. The method of claim 12, further comprising the act of turning the motor back on in the event that one of the plurality of data measurements indicates that a casing pressure falls below a predetermined value.
 14. The method of claim 13, further comprising the act of turning the motor back on in the event that the well's production increases above a predetermined value.
 15. The method of claim 14, further comprising the act of turning the motor back on in the event that a second predetermined period of time elapses.
 16. The method of claim 10, wherein the plurality of data measurements are read in analog form.
 17. The method of claim 10, wherein the plurality of data measurements include measurements related to the motor and measurements related to the well.
 18. The method of claim 10, wherein the plurality of data measurements include a data input pertaining to a physical parameter of the well.
 19. The method of claim 18, wherein the physical parameter is the length of a tubing in the well.
 20. The method of claim 10, wherein the plurality of data measurements include at least one characteristic of the motor selected from the group consisting of the motor's revolutions per minute, the motor's current consumption, or the motor's power consumption.
 21. A system for measuring data in a plurality of wells, the system comprising: a processing unit; and a plurality of sensors coupled to the processing unit and coupled to at least one well within the plurality of wells, the plurality of sensors comprising: a first sensor coupled to the at least one well within the plurality of wells, the first sensor configured to measure a casing pressure; a second sensor coupled to the at least one well within the plurality of wells, the second sensor configured to measure a tubing pressure; and a third sensor coupled to a motor that is further coupled to the at least one well within the plurality of wells, the third sensor configured to measure at least one characteristic of the motor, wherein the processing unit calculates a level of liquid in the well based upon measurements of at least two of the plurality of sensors.
 22. The system of claim 21, further comprising one or more host computers coupled to the processing unit, wherein the processing unit is located in a different geographic location from the one or more host computers.
 23. The system of claim 21, wherein each well within the plurality of wells comprises a pump situated in the well, wherein a flow rate of the pump is calculated by the processing unit when determining the liquid level.
 24. The system of claim 22, wherein the at least one characteristic of the motor is selected from the group consisting of the motor's revolutions per minute, the motor's current consumption, or the motor's power consumption.
 25. The system of claim 21, wherein a first pressure at the bottom of the well is calculated based upon one or more of the following: the tubing pressure, the at least one motor characteristic, and/or a weight associated with liquid in a tubing.
 26. The system of claim 25, wherein the weight associated with liquid in the tubing is expressed as a pressure measurement.
 27. The system of claim 25, wherein a second pressure at the bottom of the well is calculated based upon one or more of the following: the casing pressure, a weight associated with liquid in a casing, and/or a weight associated with gas in the casing.
 28. The apparatus of claim 27, wherein the first and second pressures at the bottom of the well are equated to determine the level of liquid in the well.
 29. The system of claim 21, further comprising a fourth sensor coupled to a liquid pumped to the surface by the pumping unit, wherein the processor is configured to calculate liquid flow rate using a measurement from the fourth sensor.
 30. The system of claim 21, further comprising a fifth sensor coupled to a gas flowing in an annulus, the processor configured to calculate gas flow rate using a measurement from the fifth sensor.
 31. An apparatus for measuring data from a well, the apparatus comprises: means for receiving at least one signal pertaining to the well; means for calculating a liquid level based upon the at least one signal; means for determining if the liquid level is decreasing; and in the event that the liquid level approaches a predetermined location within the well, means for shutting off a motor coupled to the well.
 32. The apparatus of claim 31, further comprising means for transmitting the at least one signal, wherein the means for transmitting is located in the well.
 33. The apparatus of claim 31, wherein the means for receiving is located within an annulus of the well.
 34. The apparatus of claim 33, wherein the means for transmitting the at least one signal includes at least one floating object.
 35. The apparatus of claim 34, wherein the at least one floating object includes an RFID transmitter.
 36. The apparatus of claim 33, wherein the means for receiving includes a wire along at least a portion of the annulus of the well.
 37. The apparatus of claim 31, wherein the means for calculating includes a processor located at the surface of the well.
 38. The apparatus of claim 31, wherein the means for receiving at least one signal is located at the surface of the well.
 39. The apparatus of claim 38, wherein the means for receiving receives a signal selected from the group consisting of the motor's revolutions per minute, the motor's current consumption, or the motor's power consumption
 40. The apparatus of claim 31, wherein the at least one signal pertains to a physical parameter of the well.
 41. The method of claim 40, wherein the physical parameter includes the length of a tubing in the well. 